Method for acquiring and processing seismic survey data using ocean bottom cables and streamers

ABSTRACT

A method is disclosed for marine seismic surveying in which upgoing and downgoing components of a seismic wavefield at a seafloor location, and the seismic wavefield at a seismic streamer location substantially above the seafloor location are determined. The upgoing and downgoing seafloor components and the streamer seismic wavefield are used to determine a separation operator. The separation operator when applied to the streamer seismic wavefield provides an estimate of at least one of an upgoing wavefield component and a downgoing wavefield component of the determined seismic wavefield for the streamer location.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF INVENTION

1. Field of the Invention

The invention relates generally to the field of seismic surveying. Moreparticularly, the invention relates to methods for acquiring andprocessing marine seismic data to determine geologic structures belowthe surface of the earth.

2. Background Art

Seismic surveying is known in the art for determining structures of rockformations below the earth's surface. Seismic surveying generallyincludes deploying an array of seismic sensors at the surface of theearth in a selected pattern, and selectively actuating a seismic energysource positioned near the seismic sensors. The energy source may be anexplosive, a vibrator, or in the case of seismic surveying performed inthe ocean (“marine seismic surveying”), one or more air guns or waterguns.

Seismic energy which emanates from the source travels through the earthformations until it reaches an acoustic impedance boundary in theformations. Acoustic impedance boundaries typically occur where thecomposition and/or mechanical properties of the earth formation change.Such boundaries are referred to as “bed boundaries”. At a bed boundarysome of the seismic energy is reflected back toward the earth's surface,where it may be detected by one or more of the seismic sensors deployedon the surface. Seismic signal processing known in the art has as one ofa number of objectives the determination of the depths and geographiclocations of bed boundaries below the earth's surface. The depth andlocation of the bed boundaries is inferred from the travel time of theseismic energy to the bed boundaries and back to the sensors at thesurface.

Marine seismic surveying known in the art includes having a vessel towone or more seismic energy sources, and the same or a different vesseltow one or more “streamers.” Streamers are cables having arrays ofseismic sensors. Typically, a seismic vessel will tow a plurality ofsuch streamers arranged to be separated by a selected lateral distancefrom each other in a pattern selected to enable relatively completedetermination of the geologic structures below the sea floor in threedimensions.

The sensors used in streamers are typically hydrophones. Hydrophones area type of sensor which generates an electrical signal or optical signalcorresponding to a change in pressure. Hydrophones known in the artinclude a transducer, such as a piezoelectric crystal, which generatesan electrical voltage when compressed. Recording equipment located onthe seismic vessel is operatively connected to the hydrophones on thestreamers, and makes a record with respect to time since actuation ofthe one or more air guns of the signal generated by each of thehydrophones.

Another type of marine seismic surveying known in the art includespositioning cables on the sea floor which include therein a plurality ofseismic sensors. These cables are known in the art as ocean bottomcables (“OBC”). In seismic surveying using OBCs, a vessel on the watersurface tows one or more seismic energy sources, and signals generatedby the seismic sensors in the OBCs are recorded.

OBCs known in the art typically include hydrophones as seismic sensors,as do streamers towed in the water. Generally speaking, marine seismicsurveys are susceptible to “ghosting” in the detected seismic signals.As is known in the art, the water surface forms an acoustic impedanceboundary with the air above, and generally reflects a substantial amountof seismic energy from “upgoing” seismic waves (waves traveling upwardlytoward the water surface). Ghosting is a particular problem in OBCsurveys because the depth of the water is typically such that surfacereflected waves are difficult to discriminate from seismic energyreflected from bed boundaries on the basis of time of arrival of theenergy at the seismic sensors.

It is known in the art to include geophones or other type of sensorwhich is responsive to particle motion (either displacement, velocity oracceleration) in OBCs. The reason for including velocity ormotion-sensitive sensors in OBCs is that these sensors are responsivenot only to the magnitude of the particle motion, but also to itsdirection. Geophones, for example, include a wire coil suspendedproximate a magnet. The coil is suspended such that it will move whenthe geophone is moved in response to seismic energy arriving at thegeophone. A voltage is generated by the coil which is related to thevelocity at which the geophone moves near the magnet. The polarity ofthe voltage is related to the direction that the geophone moves. It istherefore possible to determine the direction from which seismic energyarrives at the geophones. By combining geophone signals with hydrophonesignals, it is thus possible to determine which parts of the detectedseismic signals result from upgoing energy and which parts result from“downgoing” energy. Downgoing energy results from seismic energyreflecting off the water surface.

It is, however, relatively difficult and expensive to deploy OBCs. OBCsmust be removed from the ocean floor and redeployed at new selectedpositions along the ocean floor in order to seismically survey adifferent part of the subsurface. Each time the OBCs are redeployed, thegeographic positions of the seismic sensors must be accuratelyestablished in order that subsurface structures inferred from theseismic survey can be properly referenced geographically. Geographiccoverage using towed streamers is much more efficient because of therelative ease with which streamers can be moved through the water, andbecause the streamers are positioned near the water surface theirinstantaneous geographic position can be determined usingsatellite-based systems such as global positioning system (“GPS”)receivers. It is desirable, therefore, to have a method for acquiringseismic survey data which takes advantage of the geographic coverageability of towed streamers, with the more ghost-free images that can beobtained using OBCs.

SUMMARY OF INVENTION

In one embodiment the invention comprises a method for marine seismicsurveying in which an upgoing component and a downgoing component of aseismic wavefield at a first location on a seafloor is determined. Theseismic wavefield is also determined for a seismic streamer locationsubstantially above the seafloor location. The determined upgoing anddowngoing components of the wavefield determined for the seafloorlocation are utilized to determine a separation operator. The separationoperator, when applied to the seismic wavefield determined for thestreamer location, provides an estimate of at least one of an upgoingcomponent and a downgoing component of the seismic wavefield componentdetermined for the streamer location.

In another embodiment the invention comprises a method for marineseismic surveying in which a seismic signal is generated in a body ofwater, and seismic signals resulting from the generated signal aredetected with a motion sensor and a pressure sensor positioned at alocation on the bottom of said body of water, and with sensorspositioned in at least one streamer cable being towed in said body ofwater near the location of said sensors positioned on the bottom of saidbody of water. Signals detected by the sensors on the bottom of the bodyof water are utilized for calibrating the seismic signals detected withthe sensors positioned in the streamer cable.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows an example of marine seismic signal acquisition inaccordance with an embodiment of the invention.

FIG. 2 shows an example of marine seismic signal acquisition inaccordance with an embodiment of the invention.

FIG. 3 shows a flow chart of one embodiment of a method according to theinvention.

FIG. 4 shows a flow chart of another embodiment of a method according tothe invention.

FIG. 5 shows a flow chart of yet another embodiment of a methodaccording to the invention.

DETAILED DESCRIPTION

An example of a marine seismic data acquisition system and method thatcan be used with embodiments of the invention is shown generally inFIG. 1. A seismic vessel 10 is shown towing a streamer 12 havingsensors, typically hydrophones, 12A-12J disposed at known spaced apartpositions along the steamer 12 The vessel 10 in FIG. 1 also tows aseismic energy source 14. In some embodiments the seismic energy source14 is an air gun array. An ocean bottom cable (“OBC”) 16 is showndisposed on the sea bottom 24 at a position substantially directly belowthe position of the streamer 12. When the OBC 16 is positioned directlybelow the streamer 12, the OBC 16 will detect seismic signals related tosubstantially the same subsurface structures as the signals detected bythe hydrophones 12A-12J on the streamer 12.

The OBC 16 includes seismic sensors 16A-16J thereon at known spacedapart positions. As is known in the art, the sensors 16A-16J on the OBC16 typically include both hydrophones and geophones. Signals detected byeach of the sensors 16A-16J may be sent to a recording device 18 forlater processing which will be further explained. Typically, signalsdetected by the streamer hydrophones 12A-12J will be transmitted to andrecorded by recording equipment 11 on the seismic vessel 10. The mannerof recording and/or transmitting signals from the various sensors,including streamer hydrophones 12A-12J and OBC sensors 16A-16J shown inFIG. 1, is only meant to serve as an example of how seismic signals maybe acquired for purposes of the invention and is not intended to limitthe scope of the invention.

The recording equipment 11 includes a system (not shown separately inFIG. 1) for selectively actuating the seismic energy source 14, and forrecording detected signals time indexed with respect to initiation ofthe source 14. This time record is the reference by which signalsdetected by the OBC sensors 16A-16H and streamer hydrophones 12A-12J areindexed, as is well known in the art. The recording equipment 11 mayalso include means for receiving data (not shown) from the recordingdevice 18.

When the seismic energy source 14 is actuated, seismic energy travelsgenerally downwardly through the water 22, as shown at 30. The downgoingseismic energy 30 is partially reflected by acoustic impedanceboundaries below the sea floor 24, such as the one shown at 26 in FIG.1. Reflected energy, shown at 34, travels upwardly (“upgoing seismicenergy”) and is detected by one or more of the OBC sensors 16A-16J. Asshown at 34, the energy continues to travel upwardly through the water22 and is detected by one or more of the streamer hydrophones 12A-12J.

Some of the upgoing seismic energy 34 is reflected from water surface20, as explained in the Background section herein, because the watersurface 20 forms an acoustic impedance boundary with the air 21 above.Energy reflected from the water surface 20 is shown at 36 in FIG. 1 andis detected by the OBC sensors 16A-16J and by the hydrophones 12A-12J.

It will be understood that seismic energy propagates substantiallyspherically from a source point and from a reflection point, and thatthe seismic energy travel paths shown in FIG. 1 are for illustrationpurposes only. As is known in the art, signals from a plurality of thesensors 16A-16J and hydrophones 12A-12J may be summed or “stacked” afterappropriate correction for total travel path length in order to increasethe useful signal amplitude corresponding to selected positions alongthe impedance boundary 26. Stacking methods known in the art include,for example, common depth point (CDP) and common mid point (CMP).

The arrangement of seismic source 14, streamer 12 and OBC 16 shown inFIG. 1 is only meant to illustrate the principle of the invention. As iswell known in the art, typical arrangements for marine data acquisitionmay include additional vessels (not shown) which tow seismic sources inaddition to the source shown as 14. The seismic source or sources mayalso be towed by a vessel other than the vessel that tows the streamers.As is also known in the art, typical seismic vessels will tow aplurality of streamers arranged in a laterally spaced apart array sothat seismic signals may be rapidly and efficiently acquiredcorresponding to a relatively large area of the subsurface.

Having shown in general terms marine seismic acquisition, a method forprocessing seismic data according to the invention will now beexplained. The signals detected by the OBC sensors 16A-16J may first beprocessed, after retrieving the data stored in the recording device 18,to substantially reduce the effects of water surface reflected energy(referred to as water surface multiples). Including geophones in the OBCsensors 16A-16H, as previously explained, enables the effect of watersurface multiples to be reduced because the downgoing reflected energy,such as shown at 36, will cause a response in the hydrophones (not shownseparately) having the inverse polarity to the hydrophone response tothe upgoing energy 34.

Expressed mathematically, a total signal including both directlyarriving and reflected energy, the total signal called a “wavefield”,detected by the hydrophones in the OBC sensors 16A-16J may berepresented by the functional notation H(x, y, zf, t), where x and yrepresent coordinates related to the geographic position of eachindividual hydrophone, zf represents the depth in the water of eachhydrophone, and t represents time, typically indexed with respect toactuation time of the seismic energy source 14. Similarly, G(x, y, zf,t) may be used to represent the detected wavefield for each geophone inthe sensors OBC 16A-16J. It is known in the art that the wavefields ateach of the hydrophones and geophones are related to each other, orexpressed mathematically:

H(x,y,zf,t)=kG(x,y,zf,t)  (1)

Methods for determining the relational factor k are known in the art.For simplicity of the explanation that follows, it will be assumed thatthe relational factor has already been taken into account and that thehydrophone wavefield, H(x, y, zf, t), is equal to the geophonewavefield, G(x, y, zf, t). By convention, the sign of a compressionalenergy signal is considered to be negative if it is in a downgoingportion of the total wavefield, and is considered to be positive if itis in an upgoing portion of the total wavefield. In this case, the sumof the hydrophone signal and the geophone signal is zero for thedowngoing signal components, and is equal to twice the actual signalamplitude for the upgoing signal components. Therefore, a totalwavefield detected at the sea floor 24, represented by F, has an upgoingcomponent. F_(u), that can be represented by the expression:

F _(u)=(H+G)/2  (2)

The total wavefield also has a corresponding downgoing component, F_(d),that can be represented by the expression:

F _(d)=(H−G)/2=(G−H)/2  (3)

The total wavefield F is the sum of the upgoing F_(u) and downgoingF_(d) wavefield components, as shown in the following expression:

F=F _(u) +F _(d)  (4)

In the example acquisition system shown in FIG. 1, the total wavefielddetected by the streamer hydrophones 12A, represented by S, is similarto the total wavefield F detected by the OBC sensors 16A-16J, in thatthe total streamer wavefield S includes both upgoing and downgoingcomponents, as shown in the following expression:

S=S _(u) +S _(d)  (5)

Differences between the wavefields detected by the OBC sensors and bythe streamer hydrophones, F and S, respectively, arise from the factthat the signals detected by the OBC sensors and by the streamerhydrophones are recorded at different water depths, and as a result arerecorded in different surrounding environmental factors. Such factorsinclude, for example, the distance through the water between seismicenergy source 14 and the individual sensors, the water temperature andhydrostatic pressure, and the distance between each sensor and theparticular impedance boundary, such as the water surface 20, and thesubsurface boundary 26.

In embodiments of a method according to the invention, a propagationoperator, O, is determined, in a general sense, by comparing thestreamer detected wavefield S to the OBC-detected wavefield F. Thepropagation operator is a mathematical expression which when applied tothe OBC-detected signals produces a signal that is substantially thesame as the streamer-detected signals. Determining the propagationoperator can be explained as follows. A propagation operator for upgoingcomponents, O_(u), can be determined, which when applied to the upgoingcomponent of the sea floor wavefield, F_(u), will produce a signalequivalent to the upgoing component of the streamer wavefield, S_(u). Asimilar propagation operator may be determined for the downgoingcomponents of both the sea floor and streamer wavefields. Therelationship between the sea floor and streamer wavefield components canbe expressed mathematically by the following expressions.

O _(u) ×F _(u) =S _(u)

O _(d) ×F _(d) =S _(d)  (6)

The upgoing component operator, O_(u), may be assumed to besubstantially the inverse of the downgoing component operator, expressedas:

O _(d) =O _(u) ^(inv)  (7)

The upgoing and downgoing components of the streamer wavefield can thenbe expressed as:

O _(u) ×F _(u) =S _(u)

O _(u) ^(inv) ×F _(d) =S _(d)  (8)

The propagation operator, O, (in the form of the upgoing componentoperator O_(u), and its downgoing components inverse O_(u) ^(inv)) isdetermined when a difference between the measured streamer wavefield S,and a sum of the upgoing component operator O_(u) applied to the upgoingcomponent of the sea floor wavefield F_(u) and the downgoing componentoperator _(u) ^(inv) applied to the downgoing component of the sea floorwavefield F_(d) is a minimum. Expressed mathematically:

 (O _(u) ×F _(u) +O _(u) ^(inv) ×F _(d))−S→min  (9)

When the propagation operator, O, is determined, it then is possible toestimate the individual upgoing wavefield, S_(u), and downgoingwavefield. S_(d), components of the total streamer wavefield, S, byapplying the appropriate components of the propagation operator, O_(u)and O_(d), respectively, to the upgoing F_(u) and downgoing F_(d)wavefield components of the total OBC wavefield F.

The upgoing and downgoing components of the streamer wavefield thusdetermined may then be used to determine a streamer wavefield separationoperator, P, (“separation operator”) which separates upgoing anddowngoing components of the total streamer wavefield, S, without furtherreference to the OBC-detected wavefield, F. For data acquired as shownin FIG. 1, the separation operator P can be determined as upgoing anddowngoing component operators according to the following expression suchthat upgoing and downgoing components of the streamer wavefield aresubstantially equal to those calculated using the components of thepropagation operator:

S _(u) =S×P _(u) =F _(u) ×O _(u);

S _(d) =S×P _(d) =F _(d) ×O _(u) ^(inv)  (10)

or expressed alternatively, the separation operator is determined when adifference between the upgoing and downgoing streamer componentscalculated using the separation operator and respectively calculatedusing the propagation operator reaches a minimum:

(S×P _(u))−(F _(u) ×O _(u))→min

(S×P _(d))−(F _(d) ×O _(u) ^(inv))→min

The same upgoing and downgoing separation operator components, P_(u) andP_(d), determined from the data acquired when the streamer issubstantially directly above the OBC and shown above in equation (10)may be used, in some embodiments, to determine upgoing, S_(u), anddowngoing S_(d), wavefield components of the total streamer wavefield,S, acquired when the streamer 12 is located other than directly abovethe OBC 16. In such embodiments, the operator components P_(u) and P_(d)determined as explained above are applied to the total streamerwavefield measured when the streamer 12 is positioned other thandirectly above the OBC 16. Streamer wavefields may be acquired otherthan directly above the OBC using a single streamer positioned at suchlocations, or may be acquired using a plurality of streamers laterallyspaced apart from each other, as will be explained below with referenceto FIGS. 2, 3, 4 and 5. By using separation operators calculated asexplained above, upgoing and downgoing wavefields may be determined fora seismic survey using streamers and a limited number of OBCs. Thenumber of OBCs for a particular survey area can be substantially reducedfrom the number that would be required for a survey using only OBCs. Anexemplary embodiment of the invention can be explained with reference tothe illustration of FIG. 2 and the flow charts of FIG. 3, 4 and 5.Referring first to FIG. 2, an OBC 16 may be positioned on the oceanfloor at first location, indicated by A. A vessel 10 towing a pluralityof streamers 12, for example, eight streamers, traverses a path parallelto the lie of, and substantially directly above the position of, the OBC16. The vessel 10 may then traverse additional paths (not shown) in adirection parallel to the lie of the OBC 16, but laterally offset fromthe OBC 16 location. An amount of lateral offset of such streamer pathswith respect to the first OBC location A that will be yield acceptabledata may need to be determined for each survey, and will depend onvariations in the acoustic impedance of the subsurface.

A second location for the OBC 16 is shown in FIG. 2 at B. The secondlocation B of the OBC may use the same or a different OBC as used tosurvey the first location A. The embodiment shown in FIG. 2 contemplatesusing a second OBC 16A coupled to a second recording device 18A, butusing more than one OBC is not intended to limit the scope of theinvention. In other embodiments, a single OBC may be moved to differentlocations along the sea floor. Those skilled in the art will appreciatethat the vessel 10 may also traverse paths perpendicular to or havingother relationships with respect to the direction along which the OBC 16lies.

In some embodiments, data from the OBC 16 recorded at the first locationA may be used to determine a first propagation operator O and anassociated separation operator P. Data from the OBC 16A recorded at thesecond location B may be used to determine a second propagation operatorO and associated separation operator P.

Referring to FIG. 3, data are acquired, at 40, by both the OBC and bythe streamers as explained above with reference to FIG. 2. At 42,upgoing and downgoing components of the OBC data are separated usingtechniques known in the art. At 44, an initial estimate of upgoing anddowngoing first propagation operator components is made, which may bebased on data acquired by one of the streamers positioned substantiallydirectly above the OBC at the first location (A in FIG. 2). At 46, animproved first propagation operator is determined when the sum of thepropagated upgoing and downgoing OBC signal components most closelymatches the total steamer wavefield, as explained above with referenceto equation (9).

At 48, first separation operator components are determined, such thatthe upgoing streamer wavefield component calculated by applying theupgoing separation operator to the streamer wavefield substantiallymatches the upgoing streamer wavefield component calculated by applyingthe upgoing propagation operator component to the upgoing OBC wavefieldcomponent. Similarly, the downgoing separation operator component iscalculated such that the downgoing streamer wavefield componentcalculated by applying the downgoing separation operator to the streamerwavefield substantially matches the downgoing streamer wavefieldcomponent calculated by applying the downgoing propagation operatorcomponent to the downgoing OBC wavefield component. At 50, the firstseparation operator components are used to determine upgoing anddowngoing components of streamer data acquired at locations other thandirectly above the first location of the OBC (A in FIG. 2).

With reference to FIG. 4, in some embodiments, as shown at 58, a sum ofthe calculated upgoing and downgoing streamer components, calculatedusing the component separation operators, is checked with respect to themeasured total streamer wavefield acquired at the particular streamerlocation being evaluated. If a difference between the summed upgoing anddowngoing streamer signal components and the measured streamer signal isbelow a selected error threshold, the upgoing and downgoing componentsof streamer wavefields calculated for that location may be used, asindicated at 60.

If the error threshold is exceeded, the separation operator may beinterpolated based on the intermediate position of the streamer withrespect to the first location (A in FIG. 2) and a second OBC location(e.g., B in FIG. 2) as shown at 52. Interpolation may be performed byinterpolating between the separation operator determined for the firstlocation (A in FIG. 2) and the separation operator determined for thesecond location (B in FIG. 2). Upgoing and downgoing components of theinterpolated separation operator can be used to determine upgoing anddowngoing components of the streamer wavefields measured at theintermediate position, as shown at 56. In some embodiments, theinterpolation can be linear and related to the streamer position withrespect to both the first (A in FIG. 2) and second (B in FIG. 2) OBClocations. Interpolation procedures which may be used in suchembodiments of the invention as known in the art.

With reference to FIG. 5, alternatively, at 52, the separation operatorfor any selected streamer position, located at an intermediate locationwith respect to the first OBC location and second OBC location, may beinterpolated between two OBC positions without determining an errorbetween the measured streamer wavefield and the sum of the calculatedupgoing and downgoing streamer wavefield components. Upgoing anddowngoing components of the interpolated separation operator are thenused to determine upgoing and downgoing components of the streamerwavefields measured at the intermediate position, as shown at 56.

Interpolation as explained above may be used between any two additionalOBC locations within a particular survey area. As explained above, thenumber of OBC locations needed for a particular survey area may have tobe evaluated for each survey and will depend on such factors as theacoustic impedance of the subsurface.

Embodiments of a method according to the invention may improveefficiency of acquisition using ocean bottom cables by reducing therequired survey density of the OBC data for a particular survey area.Reducing OBC survey density may reduce the time and effort required toplace and precisely locate the sensors on the OBC.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

What is claimed is:
 1. A method for marine seismic surveying,comprising: determining an upgoing component and a downgoing componentof a seismic wavefield at a first location on a seafloor; determining,for a first seismic streamer location substantially above said firstseafloor location, the seismic wavefield of which an upgoing componentand a downgoing component is determined at said first seafloor location;and utilizing the determined upgoing component and downgoing componentof a seismic wavefield at said first location on a seafloor and thedetermined seismic wavefield for said first streamer location todetermine a separation operator, which separation operator when appliedto the determined seismic wavefield for the first streamer locationprovides an estimate of at least one of an upgoing wavefield componentand a downgoing wavefield component of said determined seismic wavefieldfor said first streamer location.
 2. The method of claim 1 furthercomprising applying said determined separation operator to seismicwavefields detected at streamer locations other than said first streamerlocation to estimate at least one of an upgoing wavefield component anda downgoing wavefield component at said other streamer locations.
 3. Themethod of claim 1 further comprising: determining an upgoing componentand a downgoing component of a seismic wavefield at a second seafloorlocation; determining, for a second seismic streamer locationsubstantially above said second seafloor location, the seismic wavefieldof which an upgoing component and a downgoing component is determined atsaid second seafloor location; utilizing the determined upgoingcomponent and downgoing component of a seismic wavefield at said secondseafloor location and the determined seismic wavefield for said secondstreamer location to determine a second separation operator, whichsecond separation operator when applied to the determined seismicwavefield for said second streamer location provides an estimate of atleast one of an upgoing wavefield component and a downgoing wavefieldcomponent of said determined seismic wavefield for said second streamerlocation; and applying interpolation procedures to the first saiddetermined separation operator and said second determined separationoperator to estimate an interpolated separation operator for a locationintermediate said first streamer location and said second streamerlocation.
 4. The method of claim 3 further comprising applying saidinterpolated separation operator to a determined seismic wavefield atsaid intermediate location to estimate at least one of an upgoingwavefield component and a downgoing wavefield component at saidintermediate location.
 5. The method of claim 3 further comprising: forsaid location intermediate said first streamer location and said secondstreamer location, determining the difference between a determinedseismic wavefield at said intermediate location and the sum of anupgoing component and a downgoing component of a wavefield estimated byapplying the first said separation operator to said determined seismicwavefield at said intermediate location; determining whether saiddifference is greater than a predetermined difference; and applying saidinterpolated separation operator to a seismic wavefield determined forsaid intermediate location if said difference is greater than a selecteddifference to estimate at least one of an upgoing wavefield componentand a downgoing wavefield component at said intermediate location.
 6. Amethod for seismic surveying, comprising: deploying an ocean bottomcable at a first seafloor location, the cable comprising at least onepressure sensor and at least one motion sensor; deploying at least oneseismic streamer at a first streamer location substantially above thefirst seafloor location, said seismic streamer having at least onepressure sensor positioned therein; actuating a seismic energy source;recording signals detected by the at least one pressure sensor and atleast one motion sensor in said ocean bottom cable at said firstseafloor location and by said pressure sensor in the streamer at saidfirst streamer location; utilizing recorded signals detected by saidseismic sensors on said first seafloor location to calculate an upgoingcomponent and a downgoing component of a seismic wavefield at said firstseafloor location; applying an upgoing propagation operator to saidupgoing component at said first seafloor location to generate anestimate of the upgoing component of said wavefield at said firststreamer location; applying a downgoing propagation operator to saiddowngoing component at said first seafloor location to generate anestimate of the downgoing component of said wavefield at said firststreamer location; determining the difference between said recordedseismic wavefield detected at said first streamer location and asummation of said estimated upgoing component and estimated downgoingcomponent of said wavefield at said first streamer location; andmodifying said upgoing propagation operator and downgoing propagationoperator so as to reduce said difference, thereby generating improvedupgoing and downgoing propagation operators.
 7. The method of claim 6further comprising determining a separation operator comprising anupgoing separation operator and a downgoing separation operator, suchthat the application of said upgoing separation operator to saidrecorded streamer signal detected at said first streamer locationresults in a signal substantially equivalent to the result of applyingsaid improved upgoing propagation operator to the upgoing component ofthe wavefield detected at the first seafloor location and theapplication of said downgoing separation operator to said recordedstreamer signal detected at said first streamer location results in asignal substantially equivalent to the results of applying said improveddowngoing propagation operator to the downgoing component of saidwavefield detected at the first seafloor location.
 8. The method ofclaim 7 further comprising applying at least one of said upgoingseparation operator and downgoing separation operator to seismicwavefields detected at locations other than substantially above saidfirst location to estimate at least one of an upgoing wavefieldcomponent and downgoing wavefield component at said other locations. 9.The method of claim 7 further comprising: determining an upgoingcomponent and a downgoing component of a seismic wavefield at a secondlocation on said seafloor; determining for a second seismic streamerlocation substantially above said second seafloor location the seismicwavefield of which an upgoing component and a downgoing component isdetermined at said second location on said seafloor; utilizing thedetermined upgoing component and downgoing component of a seismicwavefield at said second location on the seafloor and the determinedseismic wavefield for said second streamer location to determine asecond separation operator, which second separation operator whenapplied to the determined seismic wavefield for said second streamerlocation provides an estimate of at least one of an upgoing componentand a downgoing component of said determined seismic wavefield for saidsecond streamer location; and applying interpolation procedures to thefirst said determined separation operator and said second determinedseparation operator to estimate an interpolated separation operator fora location intermediate said first streamer location and said secondstreamer location.
 10. The method of claim 9 further comprising applyingsaid interpolated separation operator to a determined seismic wavefieldat said intermediate location to estimate at least one of an upgoingwavefield component and a downgoing wavefield component at saidintermediate location.
 11. The method of claim 9 further comprising: forsaid location intermediate said first streamer location and said secondstreamer location, determining the difference between a determinedseismic wavefield at said intermediate location and the sum of anupgoing component and a downgoing component of a wavefield estimated byapplying the first said separation operator to said determined seismicwavefield at said intermediate location; determining whether saiddifference is greater than a predetermined difference; and applying saidinterpolated separation operator to a seismic wavefield determined forsaid intermediate location if said difference is greater than a selecteddifference to estimate at least one of an upgoing wavefield componentand a downgoing wavefield component at said intermediate location.
 12. Amethod for marine seismic surveying, comprising: generating a seismicsignal in a body of water; detecting a seismic signal resulting fromsaid generated seismic signal with a motion sensor and a pressure sensorpositioned at a location on the bottom of said body of water; detectingseismic signals resulting from said generated seismic signal withsensors positioned in at least one streamer cable being towed in saidbody of water near the location of said sensors positioned on the bottomof said body of water; and utilizing said signals detected by saidsensors on the bottom of said body of water for calibrating said seismicsignals detected with said sensors positioned in said at least onestreamer cable.
 13. The method of claim 12 wherein utilizing saidsignals detected by said sensors on the bottom of said body of watercomprises determining a separation operator, which separation operatorwhen applied to the seismic signals detected with said sensorspositioned in said at least one streamer cable provides an estimate ofat least one of an upgoing component and a downgoing component of aseismic wavefield.
 14. The method of claim 13 wherein calibrating saidseismic signals detected with said sensors positioned in said at leastone streamer cable comprises applying said separation operator to theseismic signals detected with sensors positioned in said at least onesteamer cable to estimate at least one of an upgoing and a downgoingwavefield component of a seismic wavefield.
 15. The method of claim 13wherein determining said separation operator comprises: determining anupgoing wavefield component and a downgoing wavefield component of saidseismic signals detected at said location on the bottom of said body ofwater; and utilizing said determined upgoing component and downgoingcomponent of a seismic wavefield of said seismic signals detected atsaid seafloor location and signals detected with sensors positioned in astreamer cable at a location substantially above said location on thebottom of said body of water to determine said separation operator. 16.The method of claim 13 further comprising: detecting seismic signalsresulting from a seismic signal generated in said body of water with amotion sensor and a pressure sensor positioned at a second location onthe bottom of said body of water displaced a determinable distance fromthe first said location on the bottom of said body of water; utilizingsaid signals detected at said second location on the bottom of said bodyof water to determine a second separation operator, which secondseparation operator when applied to the seismic signals detected withsensors positioned in said at least one streamer cable being towed insaid body of water near said second location provides an estimate of atleast one of an upgoing component and a downgoing component of a seismicwavefield; and applying interpolation procedures to the first saiddetermined separation operator and the determined second separationoperator to estimate an interpolated separation operator for locationsintermediate the first said location and said second location.
 17. Themethod of claim 16 further comprising applying said interpolatedseparation operator to a determined seismic wavefield at saidintermediate locations to estimate at least one of an upgoing wavefieldcomponent and a downgoing wavefield component at said intermediatelocations.